Hydrocarbon reservoirs are exploited by drilling wells in a hydrocarbon bearing geologic formation. In primary recovery projects, producing wells (or “producers” herein) are drilled and the pressure naturally present in the reservoir drives the reservoir fluids (usually hydrocarbons and water) through the well to the surface. In secondary recovery projects, injecting wells (or “injectors” herein) are used to inject fluids into the reservoir in order to replace the fluids that have been produced, and maintain the reservoir pressure. These injectors can either be drilled anew or can be created through a conversion of an existing producer. Usually, an inexpensive fluid such as water or gas is injected in the formation for voidage replacement.
The producing wells deliver different fluids to the surface that are separated according to their phase: oil, water or gas. The fluids that can be commercialized are sold (usually oil and gas) and the fluids that are by-products of the production are disposed of (usually water and sometimes gas). The injection fluids can come from various sources. In some cases, they are unwanted production fluids, and in other cases, they are brought in from other sources such as nearby fields or pipelines, dedicated source reservoirs, etc. The injection fluids usually represent a cost for the company operating the field as they have to be separated from produced fluids or transported from other locations. The injection fluids are also often treated prior to injection to avoid creating formation damages.
Successful exploitation of an existing secondary recovery project involves maximizing the production of commercial fluids and minimizing the production of unwanted fluids as well as minimizing the injection of costly fluids. This can be achieved through continuous optimization of the production and injection strategy: controlling the flow rates and pressures of the producing and injecting wells in order to optimize the production and injection behavior.
This optimization of wells is usually performed by looking at complex reservoir or surface models, but these models are often too simplistic to truly provide insightful guidance, or are too complex to be used at the operational pace of production. In some cases, reservoir simulators may be used to forecast the production of wells in order to evaluate the possible outcomes of operational changes.
Reservoir simulators can be created in a variety of ways, but for the purpose of production optimization, the simulator should be both fast and accurate. The accuracy of the simulator is defined as the predictive power of the simulator: its ability to predict future well performance accurately and with a high level of confidence. The simulator's accuracy helps guarantee the economic success of the operational changes implemented. The speed of the simulator is defined as the time it takes to create or update a model and to perform a simulation. A fast simulator would update the model with new data in order to support daily operational decisions in a timely fashion.